Wireline Optical Fiber Sensing

ABSTRACT

The high sensitivity provided by an enhanced DAS system comprising a DAS interrogator and a high reflectivity fiber allows for the deployment of such a high reflectivity fiber as part of a wireline intervention cable which can be temporarily lowered into a well, thus avoiding the need to permanently cement such a high reflectivity optical fiber cable into the well. Instead, such a wireline cable incorporating the high reflectivity optical fiber has been found to be sensitive enough to detect micro-seismic activity and low frequency strain with many more measurement points and channels than conventional wireline deployed geophones and tiltmeters. Additionally, the cable requires no clamping and can be easily and quickly removed from one well and placed in another well.

CROSS REFERENCE TO RELATED APPLICATIONS

This non-provisional U.S. Patent Application claims priority under 35U.S.C. § 119(e) to U.S. Provisional Patent Application Ser. No.62/724,484, filed Aug. 29, 2018, the disclosure of which is herebyincorporated by reference in its entirety.

TECHNICAL FIELD

The present disclosure relates to distributed optical fiber sensors, andin particular in some embodiments to such sensors which make use of highreflectivity optical fibers, such as optical fibers with many weakreflectors distributed along the length of the sensing portion oroptical fibers with higher backscatter coefficients than usual, embeddedwithin a wireline cable deployed downhole as the sensing optical fiber.

BACKGROUND

This section provides background information related to the presentdisclosure and is not necessarily prior art.

Optical fiber based distributed sensor systems are finding manyapplications, in particular in the oil and gas industry for flowmonitoring and seismic detection, and in the security industry for areaor perimeter security monitoring, or monitoring along a long line suchas a pipeline or railway line. The present applicant, Silixa Ltd, ofElstree, London, markets two optical fiber distributed sensing systems,the Silixa® iDAS™ system, which is a very sensitive optical fiberdistributed acoustic sensor, and the Silixa® Ultima™ system, which is adistributed optical fiber based temperature sensor. Further details ofthe iDAS™ system are available at the priority date athttp://www.silixa.com/technology/idas/, and further details of theUltima™ system are available at the priority date athttp://www.silixa.com/technology/dts/. In addition, the presentapplicant's earlier International patent application WO 2010/136810gives further technical details of the operation of its distributedacoustic sensor system, the entire contents of which necessary forunderstanding the present invention being incorporated herein byreference.

Recently the applicant has found that performance improvements in termsof increased signal to noise ratio (SNR) can be obtained by usingoptical fiber with weak reflectors embedded therein along its lengthwith a DAS system. In this respect performance improvements of as muchas 20 dB have been obtained using such optical fiber. Details of such anoptical fiber and its use with the Silixa® iDAS™ system were given inour previous International patent application WO2016/142695, the entirecontents of which necessary for understanding the present disclosurebeing incorporated herein by reference. Therein we describe an improvedoptical fiber distributed acoustic sensor system that makes use of aspecially designed optical fiber to improve overall sensitivity of thesystem, in some embodiments by a factor in excess of 10. This isachieved by inserting into the fiber weak (by which we mean of lowreflectivity) broadband reflectors periodically along the fiber. Thereflectors reflect only a small proportion of the light from the DASincident thereon back along the fiber, typically in the region of 0.001%to 0.1%, but preferably around 0.01% reflectivity per reflector. Inaddition, to allow for temperature compensation, the reflectionbandwidth is relatively broadband i.e. equal or greater than the regionof +/−2 nm, preferably as large as +/−5 nm from the nominal laserwavelength. This provides for temperature dependent reflectivity of thereflectors to be accommodated, particularly where the reflectors areformed from gratings, that are known to often exhibit temperaturedependence of the reflected wavelength over a broad e.g. +/−2 nmbandwidth. In some embodiments the reflectors are formed from a seriesof fiber Bragg gratings, each with a different center reflectingfrequency, the reflecting frequencies and bandwidths of the gratingsbeing selected to provide the broadband reflection. In other embodimentsa chirped grating may also be used to provide the same effect. In otherembodiments a short grating with low reflectivity and broad bandwidthmay be written into the sensing fiber using femtosecond laser writingprocess. In some embodiments, the reflectors are spaced at the gaugelength i.e. the desired spatial resolution of the optical fiber DAS, inother embodiments the reflectors are spaced at a distance calculated independence on the gauge length, for example as a fraction or multiplethereof.

One use of Silixa's optical fiber DAS technology, including opticalfiber with weak reflectors as described above, has been to monitorhydraulic fracturing in long horizontal wells. The use of hydraulicfracturing in multi-stage long horizontal wells has been appliedsuccessfully to unconventional reservoirs. It has been customary oncertain high value “science” projects, or when drilling a new well pad,to acquire fiber optic distributed acoustic sensing data (DAS) to bothallocate the placement of fluids and proppant to the fractured stagesand record the resulting micro-seismic and low frequency strain responseand make repeat vertical seismic profiles (VSP) to optimize the wellspacing and completion design. Typically, this has been achieved bycementing a permanent fiber optic cable outside casing on one or morewells and recording DAS data during stimulation. Cementing the fiberoptic cable provides direct coupling between the cable and the formationwhich enables sufficient acoustic coupling to record the resultingmicro-seismic and low frequency strain response. Permanent installationsare both high risk due to the potential for cable breakage and increasewell costs due to the cost of a one-time cable and the additional rigtime taken to prepare the hole.

Because of the previous perceived need to permanently install an opticalfiber cable for DAS use by cementing the cable into the well, wheretemporary measurements are required conventional wireline sensing toolsare still often used. For micro-seismic and strain measurements suchtools have often been either borehole geophones or tilt-meters that aredeployed on conventional wireline. They are bulky components withlimited channels such that only a limited number of recorders can beplaced in the well and borehole geophones are unable to measure lowfrequency strain (<1 Hz). Wireline technology has been used for manyyears, and involves deploying sensors or other tools at points along a(typically braided) conductive line, which supplies power andcommunications functions to the tools and sensors. Multiple individualcontrol and power lines can be bundled together in a single wirelinecable, and it is also known to include optical fibers within the cablefor communications and downhole tool control purposes.

SUMMARY

This section provides a general summary of the disclosure, and is not acomprehensive disclosure of its full scope or all of its features.

In embodiments of the present disclosure the inventors have found thatthe high sensitivity provided by the DAS system and in particular theenhanced DAS system comprising a DAS interrogator and a highreflectivity fiber as described in our previous applicationWO2016/142695 allows for the deployment of such a high reflectivityfiber as part of a wireline intervention cable which can be temporarilylowered into a well, thus avoiding the need to permanently cement such ahigh reflectivity optical fiber cable into the well, as has been donepreviously. Instead, such a wireline cable incorporating the highreflectivity optical fiber has been found to be sensitive enough todetect micro-seismic activity and low frequency strain with many moremeasurement points and channels than conventional wireline deployedgeophones and tilt-meters. Additionally, the cable requires no clampingand can be easily and quickly removed from one well and placed inanother.

In addition to the cable being used for monitoring micro-seismic, lowfrequency strain events and vertical seismic profiles, in another use itcould be deployed into a drilled but uncompleted well whilst an adjacentwell is being drilled and detect the variation in drilling inducedvibrations that relate to differences in stress and brittleness of theformation along the long lateral section.

In one embodiment, the cable incorporating the high reflectivity fiberhas sufficient mass such that it is not buoyant in the presence ofliquids and lies against the bottom of steel casing that is cemented ina lateral oil or gas well.

Because the optical fiber with high reflectivity can be incorporatedinto conventional wireline cable very easily, conventional wirelinedeployment techniques can be used to deploy the cable downhole,including the cable being pumped or tractored into position in a lateralsection of an oil or gas well.

Embodiments of the invention provide an optical fiber distributed sensorsystem, comprising: an optical source arranged in use to produce opticalsignal pulses; an optical fiber deployable in use in an environment tobe sensed and arranged in use to receive the optical signal pulses; andsensing apparatus arranged in use to detect light from the opticalsignal pulses reflected back along the optical fiber and to determineany one or more of an acoustic, vibration, temperature or otherparameter that perturbs the path length of the optical fiber independence on the reflected light; the system being characterized inthat the optical fiber is encased in a wireline cable for deploymentdownhole.

Another embodiment provides a wireline cable having encased therein anoptical fiber adapted so as to reflect or backscatter any optical pulsestravelling there-along to a greater extent than conventional opticalfiber.

Another embodiment provides a wireline cable having encased therein anoptical fiber adapted so as to reflect or backscatter any optical pulsestravelling there-along to a greater extent than conventional opticalfiber, In one such arrangement the cable may be deployed into the wellin a “U” configuration, such that the cable extends to the bottom of thewell, and then doubles back to return back up the well. With such aU-shaped deployment the cable can be arranged such that the outward legof fiber in the cable has no reflectors therein (i.e. it is not highreflectivity cable), but then the return leg is formed from highreflectivity fiber, where the regions of improved backscatter orreflectivity are positioned in the far end of the leading fiber and maybe then continued to the top of the return fiber. In one case, the laserlight is launched down the fiber leg with no reflectors, such that thefirst reflector encountered is at the bottom of the well. This ensures agood crosstalk behaviour as the region of interest at the bottom of thewell is positioned first in the optical path, and so encounters minimalcrosstalk. Also the loud section, at the top of the well, is positionedat the end of the optical fiber and so does not contribute crosstalk tothe majority of the optical path, including the particular region ofinterest.

A yet further embodiment of the invention provides method of downholeacoustic surveying, comprising: deploying a wireline cable containing anoptical fiber downhole into a well; connecting the surface end of theoptical fiber to a distributed acoustic sensor interrogator; operatingthe interrogator to send optical pulses along the optical fiber andmeasuring the optical reflections and/or backscatter received from alongthe length of the optical fiber; after the interrogator operation,disconnecting the surface end of the optical fiber from the interrogatorand retrieving the wireline cable from within the well.

Another embodiment of the invention provides processing the determinedproperties of any acquired acoustic signals, using standard knowngeophysical data processing techniques, to determine properties of anymicroseismic, low frequency strain and/or drilling induced vibrationspresent in the vicinity of the well.

Another embodiment of the invention provides processing the determinedproperties of any acquired acoustic and temperature signals to monitorthe production profile of a well. This would involve using standardknown array processing, noise logging and thermal analysis techniques,alongside advanced acoustic processing to determine the speed of soundin the production fluid at different depths. This information indicatesin-situ fluid type and the Doppler shift between the speed of soundmodes travelling up and down in the well, and makes it possible tomeasure the fluid flow velocity and hence flow rates. Advanced acousticprocessing techniques such as these are further described inWO2010/136810 and WO2017/021740, which are incorporated herein byreference.

Further areas of applicability will become apparent from the descriptionprovided herein. The description and specific examples in this summaryare intended for purposes of illustration only and are not intended tolimit the scope of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawings described herein are for illustrative purposes only ofselected configurations and not all possible implementations, and arenot intended to limit the scope of the present disclosure. Likereference numerals refer to like parts.

FIG. 1 is a block diagram of an optical fiber provided with reflectorportions in a sensing region thereof;

FIG. 2 is a diagram illustrating the broadband reflectance of thereflector portions;

FIG. 3 is a diagram with further details of the reflector portions inthe optical fiber;

FIG. 4 is diagram illustrating the deployment of a wireline cableincorporating a high reflectivity optical fiber such as those shown inFIG. 1 or 3;

FIG. 5 is an example cross-section of a wireline cable incorporating ahigh reflectivity optical fiber such as those shown in FIG. 1 or 3;

FIG. 6 is a picture showing how the cable described herein may be usedin multiple wells in the same field;

FIG. 7 is a diagram showing how cross well strain may be measuredbetween multiple wells; and

FIG. 8 is plot of acoustic energy measured at different depths along awell versus time, as measured by a DAS system described herein using thedisclosed cable.

DETAILED DESCRIPTION

Example configurations will now be described more fully with referenceto the accompanying drawings. Example configurations are provided sothat this disclosure will be thorough, and will fully convey the scopeof the disclosure to those of ordinary skill in the art. Specificdetails are set forth such as examples of specific components, devices,and methods, to provide a thorough understanding of configurations ofthe present disclosure. It will be apparent to those of ordinary skillin the art that specific details need not be employed, that exampleconfigurations may be embodied in many different forms, and that thespecific details and the example configurations should not be construedto limit the scope of the disclosure.

Overview of Embodiments

Embodiments of the invention provide an optical fiber distributedsensor, and in some embodiments an optical fiber distributed acousticsensor that improves on the Silixa® iDAS™ system described inWO2016/142695 (the entire contents of which necessary for understandingthe invention being incorporated herein by reference) by deploying thesystem in a wireline arrangement for temporary deployment downhole. Inparticular, a wireline cable is provided that incorporates a highreflectivity optical fiber, and in particular an optical fiber havingweak reflectors embedded therein, as described in WO 2016/142695. Inalternative embodiments, however different high reflectivity fiber maybe used which is specially designed to have a high backscattercoefficient; such fibers are commercially available from companies suchas Coming Inc. Embodiments of the invention are therefore not limited tothe weak reflector fiber described in WO2016/142695, and fiber thatprovides higher backscatter than usual can also be used.

In further embodiments it has also been observed that using the DASsystem described in WO2016/142695, and also in our earlier applicationWO2010/136810, with conventional fiber (which may be single mode ormultimode, and which need not have any increased reflection orbackscatter characteristics), embedded within a wireline cable haspermitted wellbore surveying including cross-well strain andmicroseismic surveying. Therefore, in other embodiments of the inventiona high reflectivity cable need not always be used, and good results mayin some circumstances be obtained from existing conventional opticalfiber cables that may already be provided in a wireline for some otherreason, e.g. downhole communications or downhole tool control.

The wireline cable is deployed downhole in a conventional manner, but isarranged so as to be heavy enough, for example by the provision ofacoustically conducting armor surrounding the wire, that when it lies ina horizontal section of well it lies under the force of gravity againstthe bottom of the well casing or tubing (if installed), and hence isacoustically connected by the well casing to the surrounding rockstrata. This allows for good acoustic conductivity and hence sensitivityof the DAS system which is connected to the cable. A near-verticalsection of a well may also be monitored by the wireline cable providedthere is a sufficient deviation (e.g. typically >5 degrees) from thevertical to permit the cable to lie against the well casing or tubing(if installed) under the force of gravity.

Once in place, the DAS system can then detect, via the optical fiber inthe wireline cable, microseismic activity and low frequency strain withmany more measurement points and channels than conventional wirelinedeployed geophones and tiltmeters. In addition the DAS system with thewireline cable can be used to conduct vertical seismic profiles.

One of the big advantages of the use of the DAS system with a wirelinecable is that once the DAS measurements and surveys have beenundertaken, the wireline cable can be removed from the well, anddeployed for use in another well later, wherever required. Whilst thisis of course an advantage of most wireline tooling, previously thisadvantage had not been obtained with the specialist high reflectivityoptical fiber used to increase the SNR with an optical fiber DAS, asusually the fiber was cemented in place. However, being able to re-usean optical fiber cable provided with the specialist high reflectivityoptical fiber will save cost and help to reduce overall the cost of DASoperations, particularly when compared to conventional wireline acousticsurveying tools.

Although reference is made to a wireline cable it should be understoodthat any means of conveyancing an optical fiber into a wellbore thatallows the optical fiber to maintain sufficient acoustic coupling withthe wall of the wellbore will also enable the detection of microseismicactivity and low frequency strain. Alternative means of conveying a anoptical fiber into a well include slickline cable and carbon fiber rods.That is, in other embodiments the optical fiber can be incorporated intoa slickline cable for well insertion, or into carbon fiber rods for wellinsertion.

DETAILED DESCRIPTION OF AN EMBODIMENT

FIG. 1 shows an example optical fiber for use with an optical fiberdistributed sensing system, such as is already known in the art fromWO2016/142695. Here, an optical fiber 1310 is provided with a pluralityof reflector portions 1320 distributed along its length, with eachreflector portion formed from a series of Fiber Bragg Gratings 1330,being gratings written into the fiber as it is manufactured. As shown inFIG. 2, each grating has a slightly different center reflectancewavelength, with the reflectance bandwidths of the individual gratingsoverlapping to provide a broadband reflector in total. The reflectanceof each grating is relatively weak, such that thousands of reflectorsmay be placed along the fiber, ensuring that the sensor still hassignificant range.

FIG. 3 illustrates a variant on the base arrangement shown in FIGS. 1and 2. Here three sensing portions 2510, 2520, and 2530 of fiber areprovided, each provided with plural reflectors 1320. The sensingportions of fiber are dispersed at different longitudinal positionsalong the whole fiber, and are connected by transmission portions offiber within which no reflectors are provided, and hence which arerelatively low loss for carrying the optical pulses from sensing portionto sensing portion. In the arrangement of FIG. 25, however, each sensingportion 2510, 2520, and 2530 may have reflectors that reflect the samewavelengths of light, or alternatively may have reflectors that reflectdifferent, substantially non-overlapping, wavelengths of light. That is,the reflectors in the first sensing portion 2510 may reflect lightaround a μm, those of the second sensing portion 2520 reflect lightaround b μm, and those of the third sensing portion 2530 reflect lightaround c μm. At wavelengths that the reflectors don't reflect theincident light is transmitted by the reflectors with substantially noadditional loss.

With such an arrangement where the different reflectors reflectdifferent wavelengths of light the optical fiber distributed sensorsystem is able to provide spatial selectivity in terms of which set ofreflectors at which spatial location it wants to receive reflectionsfrom (and thereby enable sensing at that location), by varying thewavelengths of the transmitted pulses to match the reflector wavelengthsof the set of reflectors that are to be selected. Hence, varying thewavelengths provides the spatial selectivity of where the sensing systemwill sense, specifically which set of reflectors will providereflections from which sensing can then be undertaken.

Additionally, because the non-selected reflectors do not reflectsubstantially at the wavelengths of the pulses being transmitted alongthe fiber for the selected set of reflectors, losses from unwantedreflections are kept to a minimum, and the sensor range is increased.

Moreover, and more generally, by not having reflectors all along thefiber the system can be selective as to where it senses, and onlyprovide reflectors in those regions where sensing is required. In thepresent embodiment, as described next, that may be in those sections offiber that lie in the horizontal section of well in the production zone.With such techniques the effective range of the sensor can be increased.

The fiber of FIG. 1 or 3 is incorporated within a wireline cable, suchas the example shown in FIG. 5. A typical wireline cable 36 will have anouter sheath 42, encasing outer armor wires 44, which are armored wireswhich are helically wrapped around the cable along its length, and innerarmor wires 46, which are also helically wrapped armored wires, usuallywith a different helical pitch and/or winding sense. Inside the armoredlayers will typically by an inner electrically insulating layer 48, of asuitable thickness to electrically insulate against any high voltagesbeing carried by lines in the centre of the wireline. Any operatinglines, such as tool communication and control lines, will then be in thecentre of the wireline. In this example we show the high reflectivityoptical fiber 50 used in embodiments of the present disclosure, buttypically other control, communication, or downhole tool powerlines willalso be present.

Due to the extensive armoring and insulation, the wireline is heavierthan any liquids that would typically be found downhole, and hence willsink to the bottom surface of any horizontal sections of casing ortubing into which it is deployed, or any sections with a horizontalcomponent of direction, and maintain contact with the inner surfacethereof.

FIG. 4 shows the whole system in operation. Here an optical fiberdistributed acoustic sensor system interrogator box, such as a Silixa®iDAS™ system 32 configured as described in WO2016/142695 is providedinside a wireline deployment truck 30. The wireline deployment truck 30has conventional wireline deployment apparatus which is able to deploythe wireline 36 containing the high reflectivity cable 50 into the well34, and specifically into the horizontal production zone 38 of the well.As will be seen, the cable sits at the bottom of the well tubing orcasing, in contact therewith (the small gap shown is for illustrationpurposes only so it is clear which is the cable and which the casing ortubing). The optical fiber DAS system then operates as described inWO2016/142695 to detect high spatial resolution (typically ˜<1 m) andhigh bandwidth (typically up to ˜100 kHz) acoustic information fromalong the length of the production zone. In particular, any ofmicroseismic, low frequency strain and drilling induced vibrations canbe detected inside the wellbore using the wireline cable connected tothe DAS.

Once all of the sensing that has been undertaken in the particularwellbore has been undertaken, then in common with known wireline sensorsystems the wireline carrying the optical fiber cable can be retrievedfrom the wellbore, for deployment elsewhere. The cable would typicallybe disconnected from the DAS equipment, and wound back onto a cablereel, such that it can then be reused in the future in another wellbore.

In addition, and as noted previously, in another embodiment such a cableand DAS arrangement could be deployed into a drilled but uncompletedwell whilst an adjacent well is being drilled and detect the variationin drilling induced vibrations that relate to differences in stress andbrittleness of the formation along the long lateral section. In such acase the cable would then not lie inside the casing or tubing butinstead inside the uncompleted well, but in other respects the detailsof the cable and the DAS system would remain the same as the earlierembodiment.

Co-Location of Microseismic Events

The high sensitivity wireline cable permits reservoir monitoringconfigurations that were previously prohibitively expensive. Theinstallation of three or more permanently installed fiber optic cablesfor fracture monitoring would not have been considered as installingthese cables requires additional downhole components, additional metalmass within the cable for example, to ensure the cable is not perforatedduring any fracking operations. The risk of loss of costly cables hasbeen a barrier to the full DAS and DTS instrumentation of anunconventional reservoir.

Using two or more high sensitivity wireline cables as described hereinin conjunction with the usual permanently installed cable in anobservation well allows the colocation of microseismic events, by thesimultaneous monitoring of the depth and distance of each microseismicevent, on each permanent or wireline cable. Once the events have beendetected standard geophysical processing techniques can be used to mapthe events across the reservoir or zone of monitoring. FIGS. 6 and 7show further details.

More particularly, as shown in FIGS. 6 and 7, where multiple wells areavailable within a particular field, then the intervention cabledescribed herein can be used in conjunction with permanently installedcable in one or more of the wells to allow cross well strain to bemeasured, as described below, and also to allow co-location ofmicroseismic events. In this respect, our earlier patent applicationWO2012/168679 describes how acoustic sources such as micro-seismicevents may be detected and localised from a single DAS enabled opticalfiber cable. By using the same techniques independently on multiplecables installed or inserted into different wells in the same field thenincreased accuracy can be obtained by cross-correlating and/orcross-referencing the results from the individual cables.

Crosswell Strain

In addition to the ability to use multiple cables to locate andcross-reference microseismic events, because low frequency strain ismeasurable on the high sensitivity intervention cables described hereinthen the full fracture cycle can be monitored during frackingoperations, including critical strain effects such as the the build upof tensional and compressional strain due to the poroelastic effects inthe rock as fluid is pumped into the reservoir, followed by multiplefrac events along the well, and the subsequent closing of fractures oncepumping has ceased. FIG. 8 is a plot of acoustic energy from depth alongthe well (vertical axis) against time (horizontal axis), with higherintensity acoustic energy shown in red through to orange colours, mediumintensity acoustic energy in yellow through to green and then cyan (inorder of decreasing energy), and then lower acoustic energy shown incyan to blue colours (in decreasing energy levels). As will be seen fromFIG. 8, the increased sensitivity available from the acoustic cablesdescribed herein when used with a DAS as described allows for thevarious phases of a fracking operation to be clearly seen. Specifically,when the fracking pump is first started and fracking fluid is firstpumped into the well under hydraulic pressure, the hydraulic pressure inthe well rises, and the poroelastic effect of the surrounding rockstrata can be seen as it absorbs the increased pressure. Once thehydraulic pressure is such that the rock strata begin to fracture thenmultiple fracturing hits can be seen as the rock fractures along thewell and acoustic energy is released with each fracture. When thefracking pump is stopped and the hydraulic pressure begins to subside,further acoustic energy is generated as the various fractures that wereopened then close again, although as will be seen the acoustic energy ofthe fractures closing is less than the acoustic energy generated by theinitial fractures generated when the pump is on.

Being able to actually see the formation of individual fractures in thismanner, allows oil well engineers to measure or estimate theeffectiveness of hydraulic fracturing operations more effectively.

Various modifications, whether by way of addition, deletion, orsubstitution may be made to above mentioned embodiments to providefurther embodiments, any and all of which are intended to be encompassedby the appended claims.

What is claimed is:
 1. An optical fiber distributed sensor system,comprising: an optical source arranged in use to produce optical signalpulses; an optical fiber deployable in use in an environment to besensed and arranged in use to receive the optical signal pulses; andsensing apparatus arranged in use to detect light from the opticalsignal pulses reflected or backscattered back along the optical fiberand to determine any one or more of an acoustic, vibration, temperatureor other parameter that perturbs the path length of the optical fiber independence on the reflected light; the system being characterized inthat the optical fiber is encased in a wireline cable or a slicklinecable for deployment downhole.
 2. A system according to claim 1, whereinthe optical fiber is adapted so as to have higher reflectivity along itslength to the optical signal pulses than conventional optical fiber
 3. Asystem according to claim 2, wherein the optical fiber comprises aplurality of reflector portions distributed along its length in at leasta first sensing region thereof to thereby provide the higherreflectivity.
 4. A system according to claim 3, wherein the reflectivityof the reflector portions is: i) inversely dependent on the number ofreflector portions in the at least first sensing region; and ii)non-inversely dependent on a selected amount of crosstalk between thereflector portions in the at least first sensing region.
 5. A systemaccording to claim 2, wherein the optical fiber has a higher backscattercoefficient than conventional optical fiber.
 6. A system according toclaim 1, wherein the optical fiber is conventional single mode ormultimode fiber with conventional reflection or backscattercharacteristics.
 7. A system according to claim 1, wherein the sensingapparatus further comprises a means for processing the reflected orbackscattered light to measure the relative phase, frequency andamplitude of the received light from along the length of the opticalfiber to detect the acoustic perturbations, wherein in use the relativephase, frequency and amplitude measurements taken from along the lengthof the optical fiber are synchronized to enhance signal sensitivity. 8.A system according to claim 7, wherein the sensing apparatus furthercomprises an interferometer arranged in use to receive backscatteredand/or reflected light from along the sensing optical fiber, theinterferometer comprising at least two optical paths with a path lengthdifference therebetween, the backscattered and/or reflected lightinterfering in the interferometer to produce interference components,and wherein the means for processing comprises plural photodetectors tomeasure the interference components, and a processor arranged todetermine optical phase angle data therefrom.
 9. A system according toclaim 1, wherein the wireline cable or slickline cable is heavier thanany liquid encountered downhole such that in use the cable sinks throughany such liquid until it reaches a solid support surface.
 10. A systemaccording to claim 9, wherein the solid support surface is the bottom ofsteel casing that is cemented in a lateral oil or gas well.
 11. Awireline cable having encased therein an optical fiber adapted so as toreflect or backscatter any optical pulses travelling therealong to agreater extent than conventional optical fiber.
 12. A cable according toclaim 11, wherein the optical fiber comprises a plurality of reflectorportions distributed along its length in at least a first sensing regionthereof.
 13. A cable according to claim 12, wherein the reflectivity ofthe reflector portions is: i) inversely dependent on the number ofreflector portions in the at least first sensing region; and ii)non-inversely dependent on a selected amount of crosstalk between thereflector portions in the at least first sensing region.
 14. A cableaccording to claim 11, wherein the optical fiber has a higherbackscatter coefficient than conventional optical fiber.
 15. A cableaccording to claim 11, wherein the cable is heavier than any liquidencountered downhole such that in use the cable sinks through any suchliquid until it reaches a solid support surface.
 16. A cable accordingto claim 15, wherein the solid support surface is the bottom of steelcasing that is cemented in a lateral oil or gas well.
 17. A cableaccording to claim 12, wherein a product of the number of reflectorportions and the average reflectivity of the reflector portions is 0.1or less.
 18. A cable according to claim 11, the cable being so arrangedthat in use it is capable of being either pumped or tractored into alateral section of an oil or gas well.
 19. An optical fiber distributedsensor system according to claim 1, wherein the system is an opticalfiber distributed acoustic sensor system arranged to sense acousticsignals incident upon the cable.
 20. An optical fiber distributed sensorsystem according to claim 3, wherein a product of the number ofreflector portions and the average reflectivity of the reflectorportions is 0.1 or less.
 21. A method of downhole acoustic surveying,comprising: deploying a wireline or slickline cable containing anoptical fiber downhole into a well; connecting the surface end of theoptical fiber to a distributed acoustic sensor interrogator; operatingthe interrogator to send optical pulses along the optical fiber andmeasuring the optical reflections and/or backscatter received from alongthe length of the optical fiber; after the interrogator operation,disconnecting the surface end of the optical fiber from the interrogatorand retrieving the cable from within the well.
 22. A method according toclaim 21, and further comprising processing the optical reflection andbackscatter to determine properties of any acoustic signals incident onthe cable along its length.
 23. A method according to claim 22, andfurther comprising processing the determined properties of any acousticsignals to determine properties of any microseismic, low frequencystrain and/or drilling induced vibrations present in the vicinity of thewell.
 24. A method according to claim 21, and further comprising movinglocation to another well, and repeating the steps of the method at thatother well.
 25. A method according to claim 21, wherein the opticalfiber is adapted so as to have higher reflectivity along its length tooptical signal pulses travelling therealong than conventional opticalfiber.
 26. A method according to claim 25, wherein the high reflectivityoptical fiber comprises a plurality of reflector portions distributedalong its length in at least a first sensing region thereof.
 27. Amethod according to claim 21, wherein operating the interrogator furthercomprises processing the measured optical reflections and/or backscatterreceived from along the length of the optical fiber to measure therelative phase, frequency and amplitude of the received light from alongthe length of the optical fiber to detect acoustic perturbations,wherein in use the relative phase, frequency and amplitude measurementstaken from along the length of the optical fiber are synchronized toenhance signal sensitivity.
 28. A method according to claim 21, andfurther comprising deploying respective cables containing optical fiberinto multiple wells in the same field, connecting the respective cablesto respective DAS interrogators, and operating the DAS interrogatorssimultaneously to obtain DAS data from multiple wells simultaneously.29. A method according to claim 28, and further comprising processingthe DAS data from the multiple wells to obtain data indicative ofcross-well strain.
 30. A method according to claim 29, wherein at leastone of the optical fibers in at least one of the wells is permanentlydeployed in the at least one well, and at least one of the other opticalfibers deployed in another of the wells is retrievable from the anotherwell.
 31. A method according to claim 22, and further comprisingprocessing the determined properties of any acoustic signals todetermine any one or more of: i) a poroelastic effect within the rocksurrounding the well; ii) a hydraulic fracturing pump start and/or stoptime; iii) rock fractures opening around or in the well during hydraulicfracturing operations; iv) rock fractures closing around or in the wellafter hydraulic fracturing operations have ceased.